Southwestern Energy First Quarter 2009 Earnings Teleconference

Speakers:

Harold Korell; Chairman and Chief Executive Officer

Steve Mueller; President and Chief Operating Officer

Greg Kerley; Executive Vice President and Chief Financial Officer

Harold Korell – Chairman and Chief Executive Officer

Good morning, and thank you for joining us.  With me today are Steve Mueller, President of Southwestern, and Greg Kerley, our Chief Financial Officer.

If you have not received a copy of yesterday’s press release regarding our first quarter results, you can call (281) 618-4847 to have a copy faxed to you.  Also, I would like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are discussed in more detail in the risk factors and forward-looking statements sections of our Annual and Quarterly filings with the Securities and Exchange Commission.  Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

To begin, we had a very productive first quarter, despite the effects of the recent decline in natural gas prices. Our production from the Fayetteville Shale continues to climb as we move up the learning curve in the play. Our gross operated production from the play reached approximately 850 MMcf per day at the end of the first quarter, compared to approximately 400 MMcf per day around this time last year.

While we feel confident that natural gas prices will be higher for the longer-term, the price of gas has fallen approximately 35% from year-end 2008, thus causing a non-cash impairment of our oil and gas properties. As a result of the continuing low commodity price environment, we are reducing our planned capital program for 2009 by an additional $100 million down to $1.8 billion, which is approximately flat with our 2008 capital investments.

The important thing to know is that commodity prices move in cycles, and with the decreased drilling activity in our industry, we are now positioned for an upturn in commodity prices. With our growing production volumes and financial flexibility, Southwestern Energy is well-positioned to benefit.

I will now turn the teleconference over to Steve for more details on our E&P and Midstream activities and then to Greg for an update on our financial results. Then, we will be available for questions afterward.

Steve Mueller – President and Chief Operating Officer

Good morning.

During the 1st quarter of 2009, we produced 63.9 Bcfe, up 64% from the 1st quarter of 2008.  Our Fayetteville Shale production was 50.2 Bcf, more than double the 23.6 we produced in the 1st quarter of 2008.  We produced 7.8 Bcfe from East Texas, and 5.8 Bcfe from our conventional Arkoma properties.  As we announced yesterday, we are reducing our expected 2009 capital investment by approximately $100 million to $1.8 billion due to continued low natural gas prices.  To achieve this capital reduction, we are now planning on exiting 2009 down six rigs, four in our Fayetteville Shale Play, and two in our other producing areas.  Due to our continued strong production performance, partially offset by our reduced capital budget, we now estimate that our full year 2009 production will range from 289 to 292 Bcfe, up from 280 to 284 Bcfe.

In the 1st three months of 2009, we invested approximately $450 million in our exploration and production business activities and participated in drilling 190 wells.  Of this amount, approximately $366 million, or 81%, was for drilling wells.  Additionally, we invested $51 million in our midstream segment, almost entirely in the Fayetteville Shale.

Fayetteville Shale Play

In the 1st quarter of 2009, we invested approximately $416 million in our Fayetteville Shale play including both our E&P and midstream activities.  At March 31st, our gross operated production rate was approximately 850 MMcf per day up from 750 Mmcf per day in mid-February.  

During 2008, the majority of our gas from the Arkoma Basin was moved to markets in the Midwest, including through the Fayetteville Lateral portion of the Texas Gas Transmission, or Boardwalk Pipeline, which was placed in-service on December 24th. On April 1st, both the Fayetteville and Greenville Lateral portion of the Boardwalk Pipeline was placed in-service and we began transporting a portion of our gas to Eastern markets. On March 31st, our midstream segment was gathering approximately 920 MMcf per day through 890 miles of gathering lines in the Fayetteville Shale play area, up from approximately 470 MMcf per day a year ago.  

In April 2009, Texas Gas announced that there would be temporary reductions on the Fayetteville Lateral due to various activities, including maintenance and pipeline inspection. The exact completion date for these activities is unknown, but is expected to be complete by the end of the third quarter‎. ‎‎As a result, transportation on the Fayetteville Lateral as of April 24, 2009 was approximately 700,000 MMBtu per day.  Our capacity was approximately 500,000 MMBtu per day to Bald Knob, Arkansas including 365,000 MMBtu per day to Lula, Mississippi. We expect that the remainder of our Fayetteville Shale production will continue to be transported on other pipelines to Midwest markets until these issues are resolved.

We currently have 19 drilling rigs running here, 15 that are capable of drilling horizontal wells and 4 smaller rigs that are used to drill the vertical portion of the wells. As I mentioned previously, we are currently planning on releasing four rigs in the Fayetteville Shale play area this year.  This decrease in rig count means that we now expect to participate in approximately 600 gross wells in 2009 rather than our original plan of 650 wells.  This is approximately the same number of wells that we drilled during 2008.

Since 2007, the continuous improvement of our completion practices have resulted in fairly steady quarter-over-quarter improvements in average initial production rates of operated wells placed on production. The significant increase in the average initial production rate for the 4th quarter of 2008 and the subsequent decrease for the 1st quarter of 2009 primarily reflected the impact of the delay in the Boardwalk Pipeline. Initial rates were higher in all of the delayed wells because wells were shut-in for a longer period of time before being placed on production. In addition, we generally placed wells with the highest initial rates on production first throughout the 4th quarter of 2008. As a result, the remaining backlog of delayed wells that were placed on production in the 1st  quarter of 2009 generally had lower rates, particularly during January and February. Wells that were placed on production in January and February of 2009 had average initial production rates of 2,806 Mcf per day and 2,749 Mcf per day, respectively, while wells placed on production during March 2009 had average initial production rates of 3,375 Mcf per day. For the month of April 2009, through April 15, we have placed 27 wells on production at an average initial production rate of 3,763 Mcf per day.

We expect that our average completed well costs in 2009 will be approximately $2.9 million per well, as lower oilfield service costs are projected to more than offset higher costs associated with larger completions and longer laterals.  Our 1st quarter wells had an average completed well cost of $3.1 million per well, average horizontal lateral length of 3,874 feet and average time to drill to total depth of 12 days from re-entry to re-entry.

Because of the continued out-performance and our front end loading of drilling in our Fayetteville Shale Play, we expect production here to be between 238 and 240 Bcfe in 2009.  This is up from our previous guidance of 229 to 232 Bcfe.  

Haynesville & Marcellus

I’ll now move on to two of our newer areas – the Haynesville and Marcellus Shales.  The first horizontal well in our 50/50 joint venture with a private company targeting the Haynesville/Bossier Shale in Shelby and San Augustine Counties, Texas, the Red River 877 #1, reached total depth in the 4th quarter of 2008.  This well, which had a completed horizontal lateral of 2,718 feet, was production tested at a rate of 7.2 MMcfe per day in the first quarter of 2009 and is currently producing 3.0 Mmcf per day. The second horizontal well, the Red River 164 #1, has reached total depth with a 3,818 foot lateral, and it is expected to be completed and tested in the 2nd quarter. Pending further results from these wells, we may invest more capital in the Haynesville/Bossier Shale play than previously planned.  We currently hold approximately 17,350 net acres in the East Texas joint venture and a total of 50,110 net acres that we believe may be prospective in the Haynesville/Bossier Shale.

In the Marcellus Shale, we currently have approximately 138,600 net acres in Pennsylvania where we believe the shale is prospective. During 2008, we drilled our first four wells here, including our first horizontal well, on our acreage in Bradford and Susquehanna Counties. During the 1st quarter we increased our position in the Marcellus by approximately 23,900 acres.  

Conventional Arkoma & East Texas

Finally, we participated in drilling 9 wells in the conventional Arkoma Basin and 11 wells in East Texas during the first three months of 2009.  Nine of the East Texas wells were James Lime horizontal wells. Production from our Arkoma and East Texas properties was 5.8 and 7.8 Bcfe, respectively, for the first three months of 2009, compared to 5.9 and 8.1 Bcfe for the first three months of 2008.

Summary

In summary, we continue to have solid results in our E&P and Midstream businesses and expect continued strong results in the remainder of 2009 as demonstrated by our increase in production guidance.  We have decided to reduce our capital budget by approximately $100 million as we continue to focus on adding value during this period of reduced product prices.  As Harold mentioned, when commodity prices rebound, we will be well-positioned both financially and operationally as a growing, low-cost leader.

I will now turn it over to Greg Kerley who will discuss our financial results.

Greg Kerley – Executive Vice President and Chief Financial Officer

Thank you, Steve, and good morning.  

As you have seen from our press release, we had a very good first quarter despite the significant drop we have experienced in natural gas prices.

For the first quarter of 2009, we reported a net loss of $432.8 million, or $1.26 per share, including a $558 million after-tax ceiling test impairment of our oil and gas properties.  The significant decline in gas prices from $5.71 per MMBtu at December 31, 2008 for Henry Hub natural gas down to $3.63 at March 31, 2009 led to the ceiling test impairment.  Excluding the non-cash impairment, we recorded earnings of $125.5 million, or $0.36 per share (both non-GAAP measures reconciled below), which was a 15% increase over the prior year period.  Cash flow from operations before changes in operating assets and liabilities (a non-GAAP measure reconciled below) was up 31% to $372.6 million as our production growth more than offset lower realized natural gas prices.

Our average realized gas price during the first quarter was $5.94 per Mcf, 23% lower than our average price a year ago.  Our commodity hedge position increased our average realized gas price by $2.13 in the first quarter, which helped us offset some of the effects of lower spot market prices and widening locational market differentials (or “basis”) that occurred during the quarter.  

We currently have approximately 47% of our 2009 projected natural gas production hedged through fixed price swaps and collars at a weighted average floor price of $8.48 per Mcf.  We also have basis protected on approximately 131 Bcf of our remaining 2009 expected gas production through hedging activities and sales arrangements at a differential to NYMEX gas price of approximately $0.25 per Mcf.   Our detailed hedge position is included in our Form 10-Q filed yesterday.

Operating income for our E&P segment was $179.9 million in the first quarter of 2009, excluding the impairment charge (a non-GAAP measure reconciled below), up from $165.7 million in first quarter of 2008.  The increase was driven primarily by the 64% growth in our production volumes which more than offset the decline in our average realized gas price and higher operating costs and expenses.  

Our lease operating expenses per unit of production were $0.78 per Mcfe in the first quarter of 2009, compared to $0.77 for the same period in 2008.  The modest increase was the result of higher per unit operating costs associated with the company’s Fayetteville Shale operations, partially offset by the impact that lower natural gas prices had on the cost of compressor fuel in the first quarter of 2009.

General and administrative expenses per unit of production were $0.31 per Mcfe in the first quarter of 2009, compared to $0.42 for the same period in 2008.  The decrease was primarily due to the effects of our increased production volumes which more than offset increased compensation and related costs primarily associated with the expansion of our E&P operations.  

Taxes other than income taxes were $0.13 per Mcfe in the first quarter of 2009, compared to $0.16 for the same period in 2008, due to changes in severance and ad valorem taxes that primarily result from the mix of our production volumes and lower commodity prices.  

Our full cost pool amortization rate dropped to $1.82 in the first quarter, down from $2.30 in the prior year.  The decline was due to the combined effects of our sales of oil and gas properties during 2008, (the proceeds of which were credited to the full cost pool) and our low finding and development costs.  As a result of the ceiling test impairment charge in the first quarter, we expect that our amortization rate going forward, with all other related factors remaining constant, will be reduced by between $0.30 to $0.40 per Mcfe.  

Operating income from our Midstream Services segment grew significantly in the first quarter of 2009 to $27.4 million, up from $10.2 million in the same period in 2008.  The increase was primarily due to higher gathering revenues and an increase in the margin from our marketing activities, partially offset by increased operating costs and expenses.  

We ended the first quarter with approximately $80 million of cash on hand, nothing borrowed on our $1 billion revolving credit facility, and our debt to capitalization ratio was 25%, even after the ceiling test impairment charge.  Continuing low gas prices have impacted our projected cash flows for 2009 and as a result we have reduced our planned capital investments by approximately $100 million to end the year with approximately the same debt level as originally planned.  

We believe we are very well positioned to weather the current low commodity price environment with our strong balance sheet and financial flexibility.  That concludes my comments, so now we’ll turn back to the operator who will explain the procedure for asking questions.

Explanation and Reconciliation of Non-GAAP Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods.  

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy, diluted earnings per share attributable to Southwestern Energy stockholders and our E&P segment operating income, all which exclude certain charges or amounts.  Management presents these measures because (i) they are consistent with the manner in which the Company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three months ended March 31, 2009 and March 31, 2008.  Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.

	3 Months Ended March 31,
	2009	2008
	(in thousands)
Net income (loss) attributable to Southwestern Energy:
Net income (loss) attributable to Southwestern Energy	$    (432,830)	$     109,029
Add back:
Impairment of natural gas and oil properties (net of taxes)	558,305	--
Net income attributable to Southwestern Energy,   excluding impairment of natural gas and oil properties	$     125,475	$     109,029

	3 Months Ended March 31,
	2009	2008
Diluted earnings per share:
Net income (loss) per share attributable to   Southwestern Energy shareholders	$         (1.26)	$           0.31
Add back:
Impairment of natural gas and oil properties (net of taxes)	1.62	--
Net income per share attributable to Southwestern Energy shareholders,   excluding impairment of natural gas and oil properties	$          0.36	$           0.31

	3 Months Ended March 31,
	2009	2008
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$     407,295	$     297,087
Add back (deduct):
Change in operating assets and liabilities	(34,740)	(13,370)
Net cash provided by operating activities before changes   in operating assets and liabilities	$     372,555	$     283,717

	3 Months Ended March 31,
	2009	2008
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$    (727,893)	$     165,710
Add back:
Impairment of natural gas and oil properties	907,812	--
E&P segment operating income excluding impairment   of natural gas and oil properties	$     179,919	$     165,710

Southwestern Energy Company First Quarter 2009 Earnings Teleconference Transcript

April 28, 2009